Optimization of multistage hydraulic fracturing treatment for maximization of the tight gas productivity
Hydraulic fracturing technology is usually required to allow tight gas to escape from the low-permeability reservoir and flow through the wellbore to the surface. So far, there are no numerical tools in the petroleum industry which can optimize the whole process from geological modeling, hydraulic fracturing until production simulation with the same 3D model with consideration of the thermo-hydro-mechanical coupling. In addition, optimization design should be considered from the perspective of production, especially for multiple hydraulic fractures. Thus, the simulation of the production phase with created fractures in one model is very important for the optimization design. In this dissertation, a workflow and a numerical tool chain were developed for design and optimization of multistage hydraulic fracturing in horizontal well with regard to a maximum productivity of the tight gas wellbore. Frac-Simulator was developed to match the fracturing operation history automatically and optimize the hydraulic fracturing with consideration of thermal effect and gel-breaking. The temperature change will affect the fracture propagation process directly through the thermal stress as well as expansion or shrinkage. The temperature can also influence the fluid properties (gel breaking) as well. In order to maximize the productivity of the above mentioned tight gas wellbore, Frac-Produ Simulator was developed for the simulation of the gas production. The change of stress tensor ij and the fracture conductivity F CD during gas production are also taken into account. After the verification of the developed Simulators, a full 3D reservoir model is generated based on a real tight gas field in the North German Basin. After the history matching of the stimulation phase, the same 3D reservoir model is generated, including formations and the created fractures with their own fracture geometries and proppant concentration. The bottomhole pressure development derived from the measured treating pressure was used as input data for the stress sensitive reservoir simulation. Through analysis of simulation results, a new calculation formula of F CD was proposed, which takes the proppant position and concentration into account and can predict the gas production rate of each fracture more accurately. However, not only F CD but also proppant distribution and hydraulic connection of stimulated fractures to the well, geological structure and the interaction between fractures are determinant for the gas production volume of each fracture. Hence, the relationship between gas production rates from each fracture in the later production is different from that at the beginning. For the sensitivity analysis numerical simulations were carried out with different design parameters, including proppant type, viscosity of the injection fluid and injection time. The results show that the influences of proppant type on fracture geometry and fracture conductivity is much larger than that of the viscosity of the injection fluid, while the influences of the injection time are the smallest. For the optimal fracture treatment design different numerical simulations with varied fracture number/spacing and treatment schedule were performed. The results show that the injection rate is not the higher the better. If it is too high, the fracture width will become wider and the proppant will settle down easier to the bottom, which leads to insufficient hydraulic connection between fracture and wellbore. The fracture spacing should also not be too small, otherwise the influence area/drainage radius is not enough. Thus, there is no unique criterion to determine the optimal number and spacing of the fractures, it should be analyzed firstly in detail to the actual situation and decided then from case to case.
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